Well Treatment Fluids and Methods

ABSTRACT

A well treatment fluid includes an aqueous-based fluid, a crosslinked CMHEC polymer, and a crosslinker. The CMHEC polymer exhibits a DS of 0.2 to 0.6 and a MS of 2.0 to 2.5. The well treatment fluid exhibits a viscosity of at least about 100 cP. A well treatment method includes crosslinking a CMHEC polymer in an aqueous-based fluid at a pH of at least about 6. The crosslinking increases a viscosity of the well treatment fluid to at least about 100 cP. A well is treated with the well treatment fluid at a temperature of at least about 200° F. Another well treatment method includes forming a well treatment fluid from produced water that has a TDS content of at least about 150,000 ppm. The crosslinking increases a viscosity of the well treatment fluid to at least about 100 cP.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a divisional of and claims priority to U.S. patentapplication Ser. No. 13/961,606, filed on Aug. 7, 2013, entitled “WellTreatment Fluids and Methods,” which is incorporated herein byreference.

TECHNICAL FIELD

The embodiments herein pertain to well treatment fluids and methods,such as those using a carboxymethyl hydroxyethyl cellulose (CMHEC)polymer.

BACKGROUND

Wells drilled in low-permeability subterranean formations are oftentreated by reservoir stimulation techniques, such as hydraulicfracturing, to increase hydrocarbon production rate. High viscosityfluids may be employed to carry proppant down-hole to prop openfractures in the formation. Known linear gels (water containing agelling agent only) that can be operated at ambient temperature at thesurface generally do not exhibit a sufficiently high viscosity totransfer proppant of a large size or large quantity. Consequently,crosslinkers may be used to increase fluid viscosity, providing adequatetransport of larger proppant sizes or larger proppant quantity. Higherviscosity fluids also create wider fractures within the formation.

Guar and guar derivatives are among the most oft used polymers inhydraulic fracturing treatment. Guar derivatives, such as carboxymethylguar (CMG) and carboxymethyl hydroxypropyl guar (CMHPG), arepredominantly used in wells with a high bottom-hole temperature (BHT).In recent years, significant price increases in guar and supplyshortages of guar have posed challenges for service companies andoperators. Consequently, prices for guar derivatives have alsoincreased. Interest in cellulose derivatives has increased forfracturing treatment due to the natural abundance of cellulose. However,known systems for incorporating cellulose derivatives crosslink thepolymers only in a low pH environment. Also, known systems for usingcellulose derivatives are limited to applications in which formationtemperature is less than 250° F. due to rapid acid hydrolysis at highertemperatures.

In addition, fluid volumes in fracturing treatments have increasedsubstantially, while public concern for water use and disposal has alsoincreased. Rather than paying to treat and dispose of produced andflowback water, service companies and operators have pursued recyclingin subsequent stimulation operations. “Produced water” refers to watergenerated from hydrocarbon wells. Generally the term is used in the oilindustry to describe water that is produced along with oil and/or gas.“Flowback water” is a subcategory of produced water referring tofracturing fluid that flows back through the well, which may account forsome fraction of the original fracture fluid volume.

Produced water, especially from shale plays such as Marcellus andBakken, is known for its high total dissolved solids (TDS) and highdivalent cation content. TDS and divalent cations pose challenges forknown guar- and guar derivative-based fracturing fluids. Consequently,produced water intended for recycling in subsequent stimulationoperations is treated to obtain a water quality suitable for thefracturing fluids. Even so, such treatment is often cost-prohibitive andtime-consuming. Accordingly, other fluids suitable for higher formationtemperatures, recycling of produced water, or both are desirable.

SUMMARY

A well treatment fluid includes an aqueous-based fluid, a crosslinkedCMHEC polymer, and a crosslinker. The CMHEC polymer exhibits a degree ofsubstitution (DS) of 0.2 to 0.6 and a molar substitution (MS) of 2.0 to2.5. The crosslinker is configured to crosslink the CMHEC polymer in theaqueous-based fluid. The well treatment fluid exhibits a viscosity of atleast about 100 cP at a sheer rate of 100 sec⁻¹.

A well treatment method includes forming a well treatment fluid bycombining ingredients including an aqueous-based fluid, a CMHEC polymer,and a crosslinker. The method includes crosslinking the CMHEC polymer inthe aqueous-based fluid at a pH of at least about 6 using thecrosslinker. The crosslinking increases a viscosity of the welltreatment fluid to at least about 100 cP at a sheer rate of 100 sec⁻¹. Awell is treated with the well treatment fluid exhibiting the increasedviscosity at a temperature of at least about 200° F.

Another well treatment method includes forming a well treatment fluid bycombining ingredients including an aqueous-based fluid, a CMHEC polymer,and a crosslinker. The aqueous-based fluid is formed from produced waterthat has a TDS content of at least about 150,000 ppm and the CMHECpolymer exhibits a DS of 0.3 to 0.5 and a MS of 2.0 to 2.5. The methodincludes crosslinking the CMHEC polymer in the aqueous-based fluid usingthe crosslinker. The crosslinking increases a viscosity of the welltreatment fluid to at least about 100 cP at a sheer rate of 100 sec⁻¹. Awell is treated with the well treatment fluid exhibiting the increasedviscosity.

BRIEF DESCRIPTION OF THE DRAWINGS

Some embodiments are described below with reference to the followingaccompanying drawings.

FIG. 1 is a rheology profile graph for CMHEC at 40 pounds per thousandgallons (ppt) at various pH levels and 275° F.

FIG. 2 is a rheology profile graph for CMHEC at 50 ppt using variousconcentrations of crosslinker at pH 8.5 and 300° F.

FIG. 3 is a rheology profile graph for CMHEC at 40 ppt in produced waterusing various concentrations of crosslinker at 200° F. The pH variesslightly between 4.93 and 5.17.

FIG. 4 is a rheology profile graph for CMHEC at 40 ppt in produced waterusing various concentrations of delayed crosslinker at 200° F. The pHvaries slightly between 5.4 and 5.8.

DETAILED DESCRIPTION

Discoveries are described herein that allow use of CMHEC polymer in welltreatment fluids and methods, such as for well stimulation. Althoughprevious use of cellulose derivatives has been limited to applicationscrosslinked in a low pH environment and formation temperatures less than250° F., fluids and methods herein are not so limited. Additionally,discoveries described herein allow use of high TDS produced water asaqueous-based fluid of the well treatment fluid. The produced water mayalso have a high divalent cation content.

One polymer shown effective in providing such benefits includes CMHECpolymer exhibiting a degree of substitution (DS) of 0.2 to 0.6 and amolar substitution (MS) of 2.0 to 2.5 available from Ashland, Inc. inWayne, N.J. Accordingly, in one embodiment, a well treatment fluidincludes an aqueous-based fluid, a crosslinked CMHEC polymer, and acrosslinker. The CMHEC polymer exhibits a DS of 0.2 to 0.6 and a MS of2.0 to 2.5. The crosslinker is configured to crosslink the CMHEC polymerin the aqueous-based fluid. The well treatment fluid exhibits aviscosity of at least about 100 cP. Unless stated otherwise, viscositiesof the well treatment fluid indicated herein are exhibited at a sheerrate of 100 sec⁻¹. At a higher sheer rate, the viscosity exhibited maybe lower.

By way of example, the aqueous-based fluid may include produced water.The produced water included in the aqueous-based fluid may have a TDScontent of at least about 150,000 ppm. The produced water included inthe aqueous-based fluid may have a divalent cation content as CaCO₃ ofat least about 25,000 ppm. According to industry practice, divalentcation content may be determined by measuring the content of alldivalent cations, but expressed as equivalent CaCO₃ (hardness) contentas done herein. Depending on what proportions of the aqueous-based fluidare sourced from produced water and fresh water, the well treatmentfluid may have a TDS content of at least about 100,000 ppm and adivalent cation content as CaCO₃ of at least about 10,000 ppm. TDS anddivalent cation content may be higher for an increasing proportion ofproduced water, such as when the aqueous-based fluid is substantiallyall produced water. Accordingly, well treatment fluid TDS and divalentcation content may be least about 150,000 ppm and at least about 25,000ppm, respectively.

Observation has indicated that CMHEC polymer exhibiting a DS of 0.3 to0.5 and a MS of 2.0 to 2.5 is suitable to increase viscosity of welltreatment fluid to at least about 100 cP even when using produced waterwith the described TDS content and divalent cation content. Outside ofthe DS/MS ranges specified, a significant viscosity drop occurs. Itfollows that such a well treatment fluid may enable recycling ofproduced water, including flowback water, in subsequent stimulationoperations. Such recycling has previously posed challenges for knownguar- and guar derivative-based fracturing fluids.

Although known formulations for well treatment fluids may be able toproduce a momentary spike in viscosity, a benefit exists in a sustainedincrease in viscosity that endures throughout a stimulation process, asneeded. The well treatment fluid described herein may exhibit theviscosity of at least about 100 cP for a time of at least about 2 hours.(See FIG. 3). Known compositions and/or techniques for delaying thedevelopment of viscosity may be used to produce a desired time delay inreaching the viscosity of at least about 100 cP. Known breakers or otherbreaking techniques may be used to decrease viscosity at the appropriatetime during a stimulation process. The crosslinker may include azirconium crosslinker. Other crosslinkers or metal crosslinkers, such asaluminum or titanium, may also be suitable.

Additionally, the well treatment fluid may exhibit a pH of at leastabout 6, for example, from about 6 to about 11, including greater than 7to about 11, such as greater than 7 to about 9. The well treatment fluidmay exhibit the viscosity of at least about 100 cP even when at atemperature of at least about 200° F., for example, at least about 250°F., including at least about 275° F. and at least about 300° F.

Magnesium oxide (MgO) has shown effectiveness in producing the pH of atleast about 6. MgO dissolves slowly in the well treatment fluid toproduce magnesium hydroxide Mg(OH)₂ and keep pH at about 6 or higher.MgO solubility increases with increasing temperature, which correspondswith polymer hydrolysis that may occur at increasing temperature.Accordingly, MgO may be added to a well treatment fluid after combiningaqueous-based fluid, CMHEC polymer, and crosslinker. MgO does notsignificantly dissolve in the aqueous-based fluid at temperatures lessthan 200° F. However, as temperature increases with increasing welldepth, the risk of polymer hydrolysis at increasing temperatures alsoincreases. MgO dissolves significantly at temperatures of at least about200° F., maintaining the pH of at least about 6, for example greaterthan 7, and reducing polymer hydrolysis at depth. Other inorganiccompounds, such as oxides of Group I and II elements, may also besuitable for similar purposes.

A well treatment fluid system may incorporate the CMHEC polymer andalready including buffers or other components configured to maintain apH of at least about 6. In such circumstance, adding MgO may beunnecessary and the CMHEC polymer may be exposed to temperatures of atleast about 250° F. without polymer hydrolysis. However, MgO isavailable as an option for inclusion in well treatment fluid systemsthat are not configured to maintain pH of at least about 6 at increasedtemperatures encountered at depth.

U.S. Pat. No. 4,313,834 issued to Harris describes a treating fluidincluding an aqueous fluid, CMHEC having a DS of about 0.25 to 0.6 and aMS of about 1 to 3, and zirconium oxychloride crosslinker. Even so,Harris describes crosslinking in the presence of acid at a pH belowabout 7. Also, acceptable operation temperatures and viscositiesproduced are significantly lower in Harris compared to those describedfor the embodiments herein. As a result, the embodiments hereinrepresent significant benefits in comparison to known well treatmentfluids.

As stated above, the well treatment fluid may exhibit the increasedviscosity for an extended time. Further, the viscosity may be exhibitedeven during exposure to increased temperature. For example, the welltreatment fluid may exhibit the viscosity of at least about 100 cP for atime of at least about 2 hours when at a temperature of at least about275° F. (See FIG. 1). Also, the well treatment fluid may exhibit theviscosity of at least about 100 cP for a time of at least about 1 hourwhen at a temperature of at least about 300° F. (See FIG. 2).

The structure of the CMHEC polymer described herein allows forcrosslinking at a higher pH. Use of the higher pH further providesincreased stability at increased temperatures. For that reason, theproblems of known cellulose derivatives crosslinked under low pHconditions and subject to rapid hydrolysis at high temperatures may beovercome. Further, the DS/MS parameters of the CMHEC polymer afford thebenefit of using produced water as the aqueous-based fluid.

It will be appreciated, according to another embodiment, that a welltreatment method includes forming a well treatment fluid by combiningingredients including an aqueous-based fluid, a CMHEC polymer, and acrosslinker. The method includes crosslinking the CMHEC polymer in theaqueous-based fluid at a pH of at least about 6 using the crosslinker.The crosslinking increases a viscosity of the well treatment fluid to atleast about 100 cP at a sheer rate of 100 sec⁻¹. A well is treated withthe well treatment fluid exhibiting the increased viscosity at atemperature of at least about 200° F.

By way of example, the method may further include fracturing asubterranean formation using the well treatment fluid. The aqueous-basedfluid may include produced water, such as produced water having thecharacteristics described above. Also, the CMHEC polymer may exhibit aDS of 0.3 to 0.5 and a MS of 2.0 to 2.5 beneficial for use with producedwater. A crosslinker such as described above may further be used and pHvalues may range as described above. However, pH may instead range fromabout 3 to about 11 when using produced water.

The method may further include combining MgO as an additional ingredientbefore the crosslinking and maintaining the pH of at least about 6 atleast up to when the crosslinking occurs. The temperature may be atleast about 250° F. The well treatment fluid may exhibit the property ofstabilizing the increased viscosity of at least about 100 cP for thetimes and at the temperatures described above.

According to a further embodiment, a well treatment method includesforming a well treatment fluid by combining ingredients including anaqueous-based fluid, a CMHEC polymer, and a crosslinker. Theaqueous-based fluid is formed from produced water that has a TDS contentof at least about 150,000 ppm and the CMHEC polymer exhibits a DS of 0.3to 0.5 and a MS of 2.0 to 2.5. The method includes crosslinking theCMHEC polymer in the aqueous-based fluid using the crosslinker. Thecrosslinking increases a viscosity of the well treatment fluid to atleast about 100 cP at a sheer rate of 100 sec⁻¹. A well is treated withthe well treatment fluid exhibiting the increased viscosity.

By way of example, the method may further include fracturing asubterranean formation using the well treatment fluid. Also, theproduced water may have a divalent cation content of at least about25,000 ppm. The well treatment fluid may have a TDS content of at leastabout 100,000 ppm and a divalent cation content as CaCO₃ of at leastabout 10,000 ppm. Also, the crosslinker may be selected from thecrosslinkers described above. The well treatment fluid may exhibit theproperty of stabilizing the increased viscosity of at least about 100 cPfor a time of at least about 2 hours.

EXAMPLE 1

CMHEC with DS=0.42 and MS=2.30 was hydrated in water of differentqualities. 1.2 grams (g) CMHEC linear gel was added in 250 milliliters(mL) water placed in a blender and mixed at 1500 revolutions per minute(rpm) for 3 minutes (min). Viscosity of the linear gel was then measuredwith an OFITE M900 viscometer available from OH Testing Equipment, Inc.in Houston, Texas. Table 1 shows viscosity for 40 ppt linear gel after 3minutes of blending at 1500 rpm in Tomball tap water, 2% KCl watersolution, and 2% CaCl₂ water solution. The “as-is” pH was 8.5. Table 1illustrates that CMHEC polymer tolerates various waters well and fullyhydrates in 3 min blending at 1500 rpm even without pH adjustment.

TABLE 1 OFITE M900 Viscosity (at 300 rpm) in Tomball tap in 2% KCl in 2%CaCl₂ as-is pH~5.0 as-is pH~5.0 as-is pH~5.0 40 40 36 39 39 37

EXAMPLE 2

The CMHEC of Example 1 was tested as a crosslinked fluid. 40 ppt CMHEClinear gel hydrated in Tomball, Texas tap water was adjusted todifferent pH values (6.5-8.5) using BF-55L acid buffer available fromBaker Hughes, Inc. in Houston, Tex. 3.0 gallons per thousand gallons(gpt) zirconium-based crosslinker (XLW-22C available from Baker Hughes,Inc.) and 3 gpt gel stabilizer (GS-1L available from Baker Hughes, Inc.)were added to the fluid and it was tested on a M5500 rheometer(available from Grace Instrument Co. in Houston, Tex.) at 275° F. Asshown in FIG. 1, the fluid system maintained viscosity higher than 200cP at 100 s⁻¹ after 2 hours at pH=6.5, higher than 150 cP at pH=7, andhigher than 100 cP at pH=8.5.

EXAMPLE 3

The CMHEC of Example 1 was further tested as a crosslinked fluid. 50 ppthydrated CMHEC linear gel in Tomball, Tex. tap water was adjusted to pH8.5 and then added with 3 gpt gel stabilizer (GS-1L). The linear gel wascrosslinked with various loadings of crosslinker (XLW-22C) and resultantfluids were tested at 300° F. on a Model 5550 viscometer available fromChandler Engineering in Broken Arrow, Okla. As shown in FIG. 2, fluidwith 7 gpt and 8 gpt XLW-22C maintained viscosity over 500 cP for about1 hour at temperature, indicating tremendous thermal stability. The 6gpt sample stably maintained viscosity at over 200 cP.

EXAMPLE 4

A produced water sample was analyzed (see Table 2) from Kansas with TDSover 200,000 ppm and total hardness as CaCO₃ above 40,000 ppm asrepresentative water. Laboratory testing demonstrated that CMHEC can befully hydrated within 3 minutes (see Table 3) after 3 minutes blendingat 1500 rpm, similar to the hydration rate of guar in fresh water.

TABLE 2 Temp (F.): 72 pH: 5.73 Specific Gravity: 1.1421 Contents mg/LSodium (calc.) 68,692 Calcium 13,200 Magnesium 2,433 Barium <5 Potassium475 Iron 15 Boron 21 Si 80 Chloride 136,750 Sulfate 615 Carbonate <1Bicarbonate 51 Total Dissolved Solids (calc.) 222,232 Total Hardness asCaCO₃ 42,981

TABLE 3 OFITE M900 Viscosity (cP) (at 300 rpm RT). in Tomball tap waterin Kansas produced water Sample 3 min 3 min 25 ppt CMHEC 23 33 40 pptCMHEC 40 65

Furthermore, 40 ppt linear gel thus obtained from the above producedwater was pH adjusted with 0.2 gpt BF-55L, added with 1.0 gpt XLD-1crosslinking delayer available from Baker Hughes, Inc. in Houston, Tex.,and crosslinked with varying concentrations of zirconium crosslinkerXLW-22C. The crosslinked gel was tested at 200° F. on a FANN Model 50rheometer available from Fann Instrument Co. in Houston, Tex. Therheology shown in FIG. 3 demonstrates that the crosslinked fluidfunctions well in the aforementioned produced water and the fluid isstable for at least 2 hours.

EXAMPLE 5

40 ppt linear gel obtained from the above produced water was pH adjustedwith BF-55L, added with 1.0 gpt XLD-1 and 0.5 gpt FP-12L anti-foameravailable from Baker Hughes, Inc., and crosslinked with varyingconcentrations of delayed zirconium crosslinker XLW-60 available fromBaker Hughes, Inc. The pH ranged from 5.4 to 5.8. The crosslinked gelwas tested at 200° F. on a FANN Model 50 rheometer. The rheology shownin FIG. 4 demonstrates that the crosslinked fluid functions well in theaforementioned produced water with delayed crosslinker and the fluidviscosity is stable for at least 100 minutes. The high spikes inviscosity are caused by shear sweeps during the measurements at about 0,30, 60, and 90 min.

EXAMPLE 6

A 250 ml portion of the 40 ppt CMHEC base gel of Example 5 was measuredinto a clean WARING™ blender jar (Waring Commercial, Torrington, Conn.).Agitation was started and the rate was adjusted at 1500 rpm to exposethe blade nut and also for the reproducibility of the tests. An amountof buffer was added into the edge of the vortex of the base gel to getthe designed pH. An amount of crosslinker delayer or divalent ioninhibitor could be added into the edge of the vortex of the base gel. Anamount of crosslinker was injected into the edge of the vortex of thebase gel and a stopwatch, which set time to 0, immediately started. Whenthe viscosity increased sufficiently to allow the fluid to cover theblade nut and the vortex remained closed, the time was recorded. Thetime difference between the start of the stopwatch and the time thevortex remained closed is the vortex closure time. If the vortex did notclose within 600 sec, the test for a sample was discontinued and avortex closure time of greater than 600 sec was recorded. Such vortexclosure tests demonstrated whether the polymer crosslinking time couldbe controlled.

Table 4 shows vortex closure data at 1500 rpm for 40 ppt CMHEC inTomball tap water with buffer BF-10L (acetic acid) crosslinker XLW-22Cat room temperature.

TABLE 4 Cross- Vortex Gel linker Additives Closure (s) pH XLW-22CBF-10L, 3 gpt XLW-22C <2 4.53 XLW-22C BF-10L, 3 gpt XLW-22C <2 5.05XLW-22C BF-10L, 3 gpt XLW-22C 10 5.58 XLW-22C BF-10L, 3 gpt XLW-22C 2205.90 XLW-22C BF-10L, 3 gpt XLW-22C >600 6.58 XLW-22C BF-10L, 3 gptXLW-22C >600 7.59 XLW-22C BF-10L, 3 qpt XLW-22C >600 8.60

Table 5 shows vortex closure data at 1500 rpm for 40 ppt CMHEC inproduced water with non-delayed crosslinker, XLW-22C, delayedcrosslinkers, XLW-60 and XLW-57, at acidic condition and at roomtemperature. XLW-22C is a non-delayed crosslinker mixture of zirconiumat acidic condition. XLW-60 is a delayed crosslinker mixture ofzirconium and titanium and XLW-57 is a delayed crosslinker of zirconium.All crosslinkers are available from Baker Hughes.

TABLE 5 Cross- Vortex Gel linker Additives Closure (s) pH XLW-22C 0.8gpt BF-55L, 1 gpt XLD-1, 1.4 gpt <2 4.93 XLW-22C XLW-60 0.8 gpt BF-55L,1 gpt XLD-1, 2.2 gpt >600 5.80 XLW-60 1.2 gpt BF-55L, 1 gpt XLD-1, 2.2gpt 84 5.22 XLW-60 XLW-57 0.6 gpt BF-55L, 1 gpt XLD-1, 1.4 gpt 60 5.05XLW-57 0.8 gpt BF-55L, 1 gpt XLD-1, 1.4 gpt 11 4.98 XLW-57

In compliance with the statute, the embodiments have been described inlanguage more or less specific as to structural and methodical features.It is to be understood, however, that the embodiments are not limited tothe specific features shown and described. The embodiments are,therefore, claimed in any of their forms or modifications within theproper scope of the appended claims appropriately interpreted inaccordance with the doctrine of equivalents.

What is claimed is:
 1. A well treatment fluid comprising: anaqueous-based fluid containing produced water, the well treatment fluidhaving a total dissolved solids (TDS) content of at least about 100,000ppm; a crosslinked carboxymethyl hydroxyethyl cellulose (CMHEC) polymerexhibiting a degree of substitution (DS) of 0.3 to 0.5 and a molarsubstitution (MS) of 2.0 to 2.5; and a crosslinker configured tocrosslink the CMHEC polymer in the aqueous-based fluid, the welltreatment fluid exhibiting a property of stabilizing a sustainedviscosity of greater than or equal to about 100 cP at a sheer rate of100 sec⁻¹ for a time of at least about 1 hour when at a temperature ofat least about 200° F.
 2. The fluid of claim 1 wherein the welltreatment fluid has a TDS content of at least about 150,000 ppm.
 3. Thefluid of claim 1 wherein the well treatment fluid has a divalent cationcontent as CaCO₃ of at least about 10,000 ppm.
 4. The fluid of claim 1wherein the well treatment fluid exhibits a property of stabilizing thesustained viscosity of greater than or equal to about 100 cP at a sheerrate of 100 sec⁻¹ for a time of at least about 2 hours when at thetemperature of at least about 200° F.
 5. The fluid of claim 1 whereinthe well treatment fluid exhibits a pH of at least about
 6. 6. The fluidof claim 1 further comprising Mg(OH)₂.
 7. The fluid of claim 1 whereinthe well treatment fluid exhibits a property of stabilizing thesustained viscosity of greater than or equal to about 100 cP at a shearrate of 100 sec⁻¹ for a time of at least about 2 hours when at atemperature of at least about 275° F.
 8. The fluid of claim 1 whereinthe well treatment fluid exhibits a property of stabilizing thesustained viscosity of greater than or equal to about 100 cP at a shearrate of 100 sec⁻¹ for a time of at least about 1 hour when at atemperature of at least about 300° F.
 9. The fluid of claim 5 whereinthe pH is from greater than 7 to about
 11. 10. The fluid of claim 1wherein the temperature is at least about 250° F.
 11. The fluid of claim1 wherein the well treatment fluid has a divalent cation content asCaCO₃ of at least about 25,000 ppm.
 12. A well treatment fluidcomprising: an aqueous-based fluid formed from produced water, the welltreatment fluid having a total dissolved solids (TDS) content of atleast about 150,000 ppm and a divalent cation content as CaCO₃ of atleast about 10,000 ppm and exhibiting a pH of at least about 6; acrosslinked carboxymethyl hydroxyethyl cellulose (CMHEC) polymerexhibiting a degree of substitution (DS) of 0.3 to 0.5 and a molarsubstitution (MS) of 2.0 to 2.5; and a crosslinker configured tocrosslink the CMHEC polymer in the aqueous-based fluid, the welltreatment fluid exhibiting a property of stabilizing a sustainedviscosity of greater than or equal to about 100 cP at a sheer rate of100 sec⁻¹ for a time of at least about 1 hour when at a temperature ofat least about 200° F.
 13. The fluid of claim 12 further comprisingMg(OH)₂.
 14. The fluid of claim 12 wherein the temperature is at leastabout 250° F. and the divalent cation content as CaCO₃ is at least about25,000 ppm.
 15. The fluid of claim 12 wherein the well treatment fluidexhibits a property of stabilizing the sustained viscosity of greaterthan or equal to about 100 cP at a shear rate of 100 sec⁻¹ for a time ofat least about 2 hours when at a temperature of at least about 275° F.16. The fluid of claim 12 wherein the well treatment fluid exhibits aproperty of stabilizing the sustained viscosity of greater than or equalto about 100 cP at a shear rate of 100 sec⁻¹ for a time of at leastabout 1 hour when at a temperature of at least about 300° F.
 17. A welltreatment fluid comprising: an aqueous-based fluid formed from producedwater, the well treatment fluid having a total dissolved solids (TDS)content of at least about 150,000 ppm and a divalent cation content asCaCO₃ of at least about 10,000 ppm; Mg(OH)₂, the well treatment fluidexhibiting a pH from greater than 7 to about 11; a crosslinkedcarboxymethyl hydroxyethyl cellulose (CMHEC) polymer exhibiting a degreeof substitution (DS) of 0.3 to 0.5 and a molar substitution (MS) of 2.0to 2.5; and a crosslinker configured to crosslink the CMHEC polymer inthe aqueous-based fluid, the well treatment fluid exhibiting a propertyof stabilizing a sustained viscosity of greater than or equal to about100 cP at a sheer rate of 100 sec⁻¹ for a time of at least about 1 hourwhen at a temperature of at least about 200° F.
 18. The fluid of claim17 wherein the temperature is at least about 250° F. and the divalentcation content as CaCO₃ is at least about 25,000 ppm.
 19. The fluid ofclaim 17 wherein the well treatment fluid exhibits a property ofstabilizing the sustained viscosity of greater than or equal to about100 cP at a shear rate of 100 sec⁻¹ for a time of at least about 2 hourswhen at a temperature of at least about 275° F.
 20. The fluid of claim17 wherein the well treatment fluid exhibits a property of stabilizingthe sustained viscosity of greater than or equal to about 100 cP at ashear rate of 100 sec⁻¹ for a time of at least about 1 hour when at atemperature of at least about 300° F.